For immediate release

Nexen Reports Strong Financial Results and Bitumen Production Ramping up at Long Lake

First Quarter Highlights:

• Quarterly cash flow of $1,039 million ($1.96/share), up 74% over Q1 2007

• Record quarterly earnings of $630 million ($1.19/share), up 421% over Q1 2007

• Quarterly dividend to shareholders doubled to $0.05 per common share

• Quarterly production before royalties of 267,000 boe/d (up 12% over Q1 2007)—on track to meet annual production guidance

• Buzzard continues to outperform—quarterly production averages 212,000 boe/d gross (91,500 boe/d net)

• At Long Lake, bitumen production rates have exceeded 7,500 bbls/d (3,750 bbls/d net to us); upgrader construction is complete and commissioning underway

• Encouraging results from northeast BC shale gas production tests

	Three Months Ended March 31		Three Months Ended December 31
(Cdn$ millions)	2008	2007	2007
Production (mboe/d)1 Before Royalties After Royalties	267 222	238 191	262 214
Net Sales	1,870	1,140	1,597
Cash Flow from Operations2	1,039	598	1,079
Per Common Share ($/share)2	1.96	1.14	2.04
Net Income	630	121	194
Per Common Share ($/share)	1.19	0.23	0.37
Capital Investment, including Acquisitions	786	811	870

 

 ¹ Production includes our share of Syncrude oil sands. US investors should read the Cautionary Note to US Investors at the end of this release.

  ² For reconciliation of this non-GAAP measure see Cash Flow from Operations on pg. 8.

 

Calgary, Alberta, April 29, 2008 – Nexen delivered strong first quarter results, meeting production targets and achieving record earnings. We generated cash flow from operations of over one billion dollars for the second quarter in a row and our cash flow exceeded our capital investment by $253 million. Production averaged 267,000 boe/d (222,000 boe/d after royalties) as strong oil and gas production from our Buzzard field in the North Sea more than offset production outages at Syncrude. With solid production, attractive commodity prices and high operating margins, net income was a record $630 million.

1

Cash flow from operations totalled $1,039 million after $392 million in current income taxes. The majority of the income taxes were in the UK where Buzzard generated excellent returns from strong volumes and high cash margins. Current taxes in the fourth quarter of 2007 were significantly lower at $87 million as income from Buzzard was sheltered by tax pools which are now substantially utilized.

“I am pleased with our first quarter results as we accomplished what we set out to do,” stated Charlie Fischer, Nexen’s President and Chief Executive Officer. “We not only met our production and financial targets but completed construction at Long Lake and kept the project on schedule and within our current cost estimate.”

Oil and Gas Production

	Production before Royalties		Production after Royalties
Crude Oil, NGLs and Natural Gas (mboe/d)	Q1 2008	Q4 2007	Q1 2008	Q4 2007
North Sea	110	96	110	96
Yemen	62	66	32	34
Canada	38	37	30	31
United States	32	34	28	29
Other Countries	6	6	5	5
Syncrude	19	23	17	19
Total	267	262	222	214

Our first quarter production volumes averaged 267,000 boe/d (222,000 boe/d after royalties) as all areas met or exceeded targets with the exception of Syncrude. During the quarter, Syncrude experienced downtime as a result of cold weather and unscheduled maintenance, reducing expected quarterly volumes by over 5,000 bbls/d. In the North Sea, Buzzard performed well and contributed 91,500 boe/d (212,000 boe/d gross) compared to 75,000 boe/d (174,000 boe/d gross) in the fourth quarter of 2007. After a year of operating experience, Buzzard start up issues are behind us and facility performance is now consistently exceeding our original design expectations. We have one week of scheduled maintenance downtime planned for Buzzard in each of the second and third quarters which will reduce production volumes slightly from the first quarter. In addition, the recent shut down of the Forties pipeline due to strike action at the Grangemouth refinery in Scotland caused us to shut-in production from Buzzard, Scott/Telford and Farragon. This will reduce our production volumes for the second quarter. For the next two quarters, we also expect Syncrude’s volumes to remain at rates similar to the first quarter as two of their three cokers have planned turnarounds.

“With strong first quarter production and the ramp up of Long Lake and Ettrick later this year, we are well positioned to meet our annual guidance range of 260,000 boe/d to 280,000 boe/d,” commented Fischer.

Long Lake Project Update

During the quarter, we reached two major milestones as bitumen production began to ramp up and we completed construction of the upgrader. Total costs and project timing remain on schedule.

We are injecting steam into the reservoir through all well pads and we started converting wells to SAGD production in late February. Currently 29 of 81 well pairs have been converted to SAGD.  While early producton rates are variable, total bitumen production is averaging 6,200 bbls/d with peak rates to date in excess of 7,500 bbls/d (3,750 bbls/d net to us). During the first quarter, we started up the first cogeneration unit which has reliably produced power in excess of 80 megawatts. Surplus power was sold into the Alberta power grid. We recently started up the second cogeneration unit and we expect it to be fully operational shortly. We expect to convert the remaining well pairs to SAGD by mid summer.

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This will allow bitumen production to grow to full rates over the next 6 to 12 months. The bitumen production capacity of the SAGD facilities is approximately 72,000 bbls/d (36,000 bbls/d net to us).

“We are encouraged by the early production results and build up of reservoir pressure at Long Lake,” said Fischer. “Based on two months of data, our bitumen production and SOR rates are meeting our expectations. We are confident we will have sufficient feedstock for the start up of the upgrader.”

With construction of the upgrader complete, we have turned over all units and systems to operations. We estimate that commissioning is over 50% complete and we plan to start introducing hydrocarbons into key processing units in May. Last week while introducing oxygen into a liquid oxygen tank the tank roof was damaged.  We are presently investigating the cause of the damage and implementing solutions to keep the ugrader startup process on track.  Our start up schedule forecasts production of synthetic crude to ramp up to full rates over a 12 to 18 month period following initial upgrader start up. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) of premium synthetic crude.

This project only develops about 10% of our oil sands leases. We plan to increase synthetic crude oil production as we sequentially develop our lands in 60,000 bbls/d (30,000 bbls/d net to us) phases using technologies developed at Long Lake.

“We are excited about bringing our first integrated insitu oil sands project on stream in the coming months,” stated Fischer. “The project, which is designed to produce one of the highest quality crudes in North America, is progressing as planned and once Long Lake is fully ramped up, we expect to enjoy a significant margin improvement over competing technologies as our energy costs will be significantly reduced. This project will generate significant value for our shareholders.”

Work continues on Phase 2 and our goal is to sanction this phase by year end. However, ultimate timing depends on accumulating sufficient operating history from Phase 1 and receiving clarity on proposed regulatory changes such as climate change. Proposed federal climate change regulations indicate a move towards carbon capture and sequestration. With the addition of shift reactors to future phases, our unique process allows for the pre-combustion capture of green house gas emissions for future sequestration.

North Sea Update—Ettrick Development Progressing Towards First Oil

Our Ettrick development in the North Sea is progressing towards first oil in the second half of 2008. The development will utilize a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. Construction of the FPSO is nearly complete and sea trials are expected to commence mid year.

We have also identified a number of exploration opportunities in the immediate area that could be future tie-backs to Ettrick. We recently spud one of these opportunities, Blackbird, and have plans to drill another one later this year. We operate both Ettrick and Blackbird with an 80% working interest in each. We plan to drill six exploration wells in total in the UK North Sea before year end.

“Our North Sea strategy is to grow our production here with exploration and exploitation opportunities near existing infrastructure,” commented Fischer. “We currently have a number of satellite discoveries near our Buzzard, Scott/Telford, Ettrick and third party facilities that in aggregate have sizeable potential. We are currently assessing development options for these discoveries.”

Shale Gas Update

Over the past 18 months, we have accumulated a substantial land position of approximately 123,000 net acres in an emerging Devonian shale gas play in the Horn River Basin in northeast British Columbia which has the potential to become one of the most significant shale gas plays in North America. We have a 100% working interest in these lands. Our capital program over the past two winters has primarily focused on the Dilly Creek area in the Horn River Basin where we have approximately 85,000 net acres.

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This shale gas play has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. The average gross shale thickness on our Dilly Creek lands is approximately 175 meters which is almost 50% thicker than the Barnett.

We recently announced positive results from our winter program where we fraced three vertical wells and one horizontal well with encouraging results. Based on our assessment of the data we acquired, additional analysis conducted by third party consultants and assuming a 20% recovery factor, we estimate our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resources. Further appraisal activity is required before these estimates can be finalized and commerciality established.

“There has been a lot of excitement over this play and we are very pleased to be a large part of it,” commented Fischer. “We are well positioned with significant acreage that is surrounded by wells drilled by other major players in the area who have experienced strong production test results. Based on our winter program results, we believe our reservoir is comparable to those offsetting our lands.”

To further assess the potential of our lands, we are currently engaged in consultations with various stakeholders and are gearing up to conduct a summer drilling program consisting of two horizontal wells which will be fraced, completed and tied-in. We recently participated in the construction of an all-season road, providing us access to these well locations and approximately half of our Dilly Creek lands year round.

Coalbed Methane (CBM) Development Continues

In Canada, we continue to develop CBM from Mannville coals in the Fort Assiniboine area and well performance continues to meet expectations. The Government of Alberta recently provided clarification of the length adjustment to be used for calculation of the proposed royalties and we are reviewing our investment program in light of this announcement. Our production from this area averaged 34 mmcf/d for the quarter and we expect to exit the year around 46 mmcf/d as our existing wells dewater and production increases.

Gulf of Mexico Update

In the Eastern Gulf of Mexico, where we have interests in discoveries at Vicksburg and Shiloh, we increased our acreage position on an unpromoted basis by acquiring working interests of 25% in 33 blocks recently awarded to Shell from the lease sale in late 2007. A number of additional exploration opportunities have been identified in the region and plans are in place to spud one of these opportunities, Fredricksburg, in the next few months. We have a 20% interest in Shiloh, a 25% interest in Vicksburg and a 20% interest in Fredricksburg, with Shell operating all three.

“We are excited about the Eastern Gulf of Mexico,” stated Fischer. “When we combine discoveries at Vicksburg and Shiloh with the prospects we see on our land holdings, this area has the potential to become a significant part of our Gulf of Mexico business.”

Elsewhere in the Gulf of Mexico, we sanctioned development of our Longhorn discovery during the quarter. Development will consist of three subsea wells tied-back to the non-operated Crystal facility. First production is expected in 2009 with a peak production rate of approximately 200 mmcf/d gross. We have a 25% non-operated working interest and Eni is the operator.

To date, we have not been able to find a rig with the capability of drilling a delineation well at Knotty Head. As a result, we plan to drill an appraisal well in mid 2009 when our first new deep-water drilling rig arrives. We have a 25% operated interest in the field.

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Offshore West Africa

During the quarter, we commenced development of the Usan field, offshore Nigeria. The field development plan includes a floating production, storage and offloading vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities have been awarded and contractors are mobilizing for detailed engineering and project execution. Our capital investment is expected to be within the range of US$1.6 to US$2.0 billion over the development period, with an estimated 2008 capital commitment of approximately US$300 million. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us).

The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic in anticipation of further exploratory drilling in the area. The Usan field was discovered in 2002 and is located approximately 100 kilometers offshore in water depths ranging from 750 to 850 meters. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).

Excess Cash Flow

In 2008, we expect to generate substantial cash flow in excess of capital investment that can be used to reduce debt, fund additional capital investment programs and repurchase shares.

“As we look to invest our cash flow, we consider all options to create additional value for shareholders,” commented Fischer.

Increased Quarterly Dividend

The Board of Directors has declared an increase in the quarterly dividend to $0.05 per common share payable July 1, 2008, to shareholders of record on June 10, 2008. This doubles the dividend from the previous rate. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.

Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as coalbed methane and shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection.

Information with respect to forward-looking statements and cautionary notes is set out below.

For further information, please contact:

Michael J. Harris, CA

Vice President, Investor Relations

(403) 699-4688

Lavonne Zdunich, CA

Analyst, Investor Relations

(403) 699-5821

5

Tim Chatten, P.Eng

Analyst, Investor Relations

(403) 699-4244

801 – 7^th Ave SW

Calgary, Alberta, Canada T2P 3P7

www.nexeninc.com

Conference Call

Charlie Fischer, President and CEO, and Marvin Romanow, Executive Vice-President and CFO, will host a conference call to discuss our financial and operating results and expectations for the future.

Date:	April 29, 2008
Time:	12:30 p.m. Mountain Time (2:30 p.m. Eastern Time)

To listen to the conference call, please call one of the following:

416-641-2140 (Toronto)

800-952-4972 (North American toll-free)

800-6578-9898 (Global toll-free)

A replay of the call will be available for two weeks starting at 2:30 p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3250781 followed by the pound sign. A live and on demand webcast of the conference call will be available at www.nexeninc.com .

Forward-Looking Statements

Certain statements in this report constitute “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (“forward-looking statements”) are generally identifiable by the terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook” or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset dispositions, future sources of funding for our capital program, future debt levels, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future cash flows and their uses, future drilling of new wells, ultimate recoverability of reserves or resources, expected finding and development costs, expected operating costs, future demand for chemicals products, estimates on a per share basis, sales, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed or will come on stream, and changes in any of the foregoing are forward-looking statements. Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2007 Annual Report on Form 10-K for further discussion of the risk factors.

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Cautionary Note to US Investors

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to discuss only proved reserves that are supported by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. In this disclosure, we may refer to “recoverable reserves”, “probable reserves” and “recoverable resources” which are inherently more uncertain than proved reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.

In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company’s share of Syncrude.

Under SEC regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil we will produce and sell from Long Lake.

Cautionary Note to Canadian Investors

Nexen is required to disclose oil and gas activities under National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (NI 51-101). However, the Canadian securities regulatory authorities (CSA) have granted us exemptions from certain provisions of NI 51-101 to permit US style disclosure. These exemptions were sought because we are a US Securities and Exchange Commission (SEC) registrant and our securities regulatory disclosures, including Form 10-K and other related forms, must comply with SEC requirements. Our disclosures may differ from those of Canadian companies who have not received similar exemptions under NI 51-101.

Please read the “Special Note to Canadian Investors” in Item 7A in our 2007 Annual Report on Form 10-K, for a summary of the exemption granted by the CSA and the major differences between SEC requirements and NI 51-101. The summary is not intended to be all-inclusive or to convey specific advice. Reserve estimation is highly technical and requires professional collaboration and judgment.

Because reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.

Please note that the differences between SEC requirements and NI 51-101 may be material.

Our probable reserves disclosure applies the Society of Petroleum Engineers/World Petroleum Council (SPE/WPC) definition for probable reserves. The Canadian Oil and Gas Evaluation Handbook states there should not be a significant difference in estimated probable reserve quantities using the SPE/WPC definition versus NI 51-101.

Resources

Nexen’s estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, and general uncertainties associated with this early stage of evaluation.

The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources.

Nexen’s estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes.

Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

In this disclosure, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.

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Nexen Inc.

Financial Highlights

	Three Months
	Ended March 31
(Cdn$ millions)		2008	2007
Net Sales		1,870	1,140
Cash Flow from Operations		1,039	598
Per Common Share ($/share) 1		1.96	1.14
Net Income		630	121
Per Common Share ($/share) 1		1.19	0.23
Capital Investment, including Acquisitions 2		786	811
Net Debt 3		4,059	4,939
Common Shares Outstanding (millions of shares) 1		529.4	526.4

 

¹  Restated to reflect a two-for-one stock split in the second quarter of 2007.

² Includes oil and gas development, exploration, and expenditures for other property, plant and equipment.

³ Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.

 

Cash Flow from Operations ¹

	Three Months
	Ended March 31
(Cdn$ millions)		2008	2007
Oil & Gas and Syncrude
Yemen 2		165	158
Canada		86	44
United States		147	133
United Kingdom		880	291
Other Countries		34	7
Marketing		13	1
Syncrude		90	67
		1,415	701
Chemicals		13	23
		1,428	724
Interest and Other Corporate Items		(64)	(110)
Income Taxes 3		(325)	(16)
Cash Flow from Operations 1		1,039	598

 

¹ 





Defined as cash flow from operating activities before changes in non-cash working capital and other. We evaluate our performance and that of our business segments based on earnings and cash flow from operations. Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other and excludes items of a non-recurring nature. We consider it a key measure as it demonstrates our ability and the ability of our business segments to generate the cash flow necessary to fund future growth through capital investment and repay debt. Cash flow from operations may not be comparable with the calculation of similar measures for other companies.

	Three Months
	Ended March 31
(Cdn$ millions)	2008	2007
Cash Flow from Operating Activities	1,168	448
Changes in Non-Cash Working Capital	(140)	(32)
Other	17	189
Amortization of Premium for Crude Oil Put Options	(6)	(7)
Cash Flow from Operations	1,039	598
Weighted-average Number of Common Shares Outstanding (millions of shares)	528.9	526.0
Cash Flow from Operations Per Common Share ($/share)	1.96	1.14

² After in-country cash taxes of $67 million for the three months ended March 31, 2008 (2007 – $44 million).

³ Excludes in-country cash taxes in Yemen.

 

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Nexen Inc.

Production Volumes (before royalties) ¹

	Three Months
	Ended March 31
		2008	2007
Crude Oil and NGLs (mbbls/d)
Yemen		62.2	77.1
Canada		16.9	17.8
United States		13.7	21.6
United Kingdom		106.0	55.6
Other Countries		6.0	5.8
Syncrude (mbbls/d) 2		19.3	21.4
		224.1	199.3
Natural Gas (mmcf/d)
Canada		127	118
United States		112	101
United Kingdom		21	14
		260	233
Total Production (mboe/d)		267	238

Production Volumes (after royalties)

	Three Months
	Ended March 31
		2008	2007
Crude Oil and NGLs (mbbls/d)
Yemen		31.8	45.0
Canada		12.9	14.2
United States		12.0	19.3
United Kingdom		106.0	55.6
Other Countries		5.5	5.4
Syncrude (mbbls/d) 2		17.0	18.9
		185.2	158.4
Natural Gas (mmcf/d)
Canada		107	95
United States		95	86
United Kingdom		21	14
		223	195
Total Production (mboe/d)		222	191

Notes:

 

¹  We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies.

   

² Considered a mining operation for US reporting purposes.

 

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Nexen Inc.

Oil and Gas Prices and Cash Netback ¹

							Total
	Quarters – 2008		Quarters – 2007				Year
(all dollar amounts in Cdn$ unless noted)		1st	1st	2nd	3rd	4th	2007
PRICES:
WTI Crude Oil (US$/bbl)		97.90	58.16	65.03	75.38	90.69	72.31
Nexen Average – Oil (Cdn$/bbl)		93.00	61.69	72.27	75.86	82.80	73.43
NYMEX Natural Gas (US$/mmbtu)		8.75	7.18	7.66	6.24	7.39	7.12
Nexen Average – Gas (Cdn$/mcf)		7.97	7.58	7.52	5.80	6.47	6.81
NETBACKS:
Canada – Heavy Oil
Sales (mbbls/d)		16.2	17.8	17.2	16.9	16.4	17.1
Price Received ($/bbl)		65.94	41.71	41.89	46.76	46.07	44.07
Royalties & Other		16.65	9.16	9.52	10.93	10.04	9.91
Operating Costs		15.76	13.65	15.14	14.53	15.22	14.62
Netback		33.53	18.90	17.23	21.30	20.81	19.54
Canada – Natural Gas
Sales (mmcf/d)		127	118	116	112	124	118
Price Received ($/mcf)		7.57	7.16	7.06	5.17	5.88	6.32
Royalties & Other		1.18	1.26	1.09	0.78	0.86	1.00
Operating Costs		1.67	1.59	1.81	2.52	1.71	1.90
Netback		4.72	4.31	4.16	1.87	3.31	3.42
Yemen
Sales (mbbls/d)		62.5	77.5	72.7	69.9	66.2	71.5
Price Received ($/bbl)		96.57	63.02	77.34	78.27	88.24	76.29
Royalties & Other		48.07	28.17	33.84	34.73	43.04	34.69
Operating Costs		7.76	6.07	6.29	6.72	7.24	6.56
In-country Taxes		11.82	6.38	9.89	10.03	12.18	9.52
Netback		28.92	22.40	27.32	26.79	25.78	25.52
Syncrude
Sales (mbbls/d)		19.3	21.4	19.0	25.2	22.6	22.1
Price Received ($/bbl)		101.70	70.03	77.12	82.09	88.33	79.76
Royalties & Other		11.93	8.26	10.33	13.42	15.33	12.02
Operating Costs		35.16	24.40	29.91	22.37	27.52	25.80
Netback		54.61	37.37	36.88	46.30	45.48	41.94

 

¹ Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen.

 

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Nexen Inc.

Oil and Gas Cash Netback ¹(continued)

							Total
	Quarters – 2008		Quarters – 2007				Year
(all dollar amounts in Cdn$ unless noted)		1st	1st	2nd	3rd	4th	2007
United States
Crude Oil:
Sales (mbbls/d)		13.7	21.6	16.0	14.1	13.9	16.4
Price Received ($/bbl)		94.07	58.49	68.18	74.43	84.33	69.83
Natural Gas:
Sales (mmcf/d)		112	101	86	98	119	101
Price Received ($/mcf)		9.03	8.58	8.85	6.75	7.27	7.80
Total Sales Volume (mboe/d)		32.4	38.4	30.4	30.5	33.8	33.3
Price Received ($/boe)		71.10	55.44	61.04	56.28	60.32	58.16
Royalties & Other		9.53	6.78	7.71	7.28	8.13	7.45
Operating Costs		8.20	8.11	9.46	7.40	8.78	8.43
Netback		53.37	40.55	43.87	41.60	43.41	42.28
United Kingdom
Crude Oil:
Sales (mbbls/d)		108.9	58.8	87.2	83.6	94.5	81.1
Price Received ($/bbl)		93.38	64.33	74.07	78.06	84.06	76.30
Natural Gas:
Sales (mmcf/d)		22	13	13	16	21	16
Price Received ($/mcf)		6.82	3.87	3.32	4.99	5.84	4.71
Total Sales Volume (mboe/d)		112.6	60.8	89.3	86.3	98.0	83.7
Price Received ($/boe)		91.67	62.92	72.75	76.56	82.29	74.79
Operating Costs		5.67	9.60	6.59	6.28	6.23	6.94
Netback		86.00	53.32	66.16	70.28	76.06	67.85
Other Countries
Sales (mbbls/d)		6.0	5.8	6.2	6.5	6.2	6.2
Price Received ($/bbl)		91.85	59.81	68.04	76.29	79.74	71.29
Royalties & Other		7.46	4.80	5.62	6.46	6.60	5.90
Operating Costs		4.74	2.97	3.39	3.34	4.13	3.45
Netback		79.65	52.04	59.03	66.49	69.01	61.94
Company-Wide
Oil and Gas Sales (mboe/d)		270.1	241.5	254.1	253.9	263.9	253.4
Price Received ($/boe)		85.90	59.13	68.48	69.82	75.50	68.46
Royalties & Other		14.87	12.26	12.65	13.02	14.37	13.10
Operating Costs		9.46	9.67	9.41	9.26	9.46	9.45
In-country Taxes		2.74	2.05	2.83	2.76	3.05	2.69
Netback		58.83	35.15	43.59	44.78	48.62	43.22

 

¹ Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen.

 

11

Nexen Inc.

Unaudited Consolidated Statement of Income

For the Three Months Ended March 31

(Cdn$ millions, except per share amounts)	2008	2007
Revenues and Other Income
Net Sales	1,870	1,140
Marketing and Other (Note 15)	222	248
	2,092	1,388
Expenses
Operating	309	290
Depreciation, Depletion, Amortization and Impairment	364	334
Transportation and Other	205	246
General and Administrative	55	202
Exploration	32	49
Interest (Note 6)	27	48
	992	1,169
Income before Income Taxes	1,100	219
Provision for Income Taxes
Current	392	60
Future	77	35
	469	95
Net Income before Non-Controlling Interests	631	124
Less: Net Income Attributable to Non-Controlling Interests	(1)	(3)
Net Income	630	121
Earnings Per Common Share ($/share)
Basic (Note 13)	1.19	0.23
Diluted (Note 13)	1.17	0.22

See accompanying notes to the Unaudited Consolidated Financial Statements.

12

Nexen Inc.

Unaudited Consolidated Balance Sheet

		March 31	December 31
(Cdn$ millions, except share amounts)		2008	2007
Assets
Current Assets
Cash and Cash Equivalents		524	206
Restricted Cash		75	203
Accounts Receivable (Note 2)		4,041	3,502
Inventories and Supplies (Note 3)		755	659
Future Income Tax Assets		25	18
Other		84	71
Total Current Assets		5,504	4,659
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $7,703 (December 31, 2007 – $7,195)		13,139	12,498
Future Income Tax Assets		263	268
Deferred Charges and Other Assets (Note 4)		418	324
Goodwill		337	326
Total Assets		19,661	18,075
Liabilities and Shareholders’ Equity
Current Liabilities
Current Portion of Long-Term Debt (Note 6)		125	-
Accounts Payable and Accrued Liabilities		4,894	4,180
Accrued Interest Payable		67	54
Dividends Payable		13	13
Total Current Liabilities		5,099	4,247
Long-Term Debt (Note 6)		4,458	4,610
Future Income Tax Liabilities		2,415	2,290
Asset Retirement Obligations (Note 8)		814	792
Deferred Credits and Other Liabilities (Note 9)		525	459
Non-Controlling Interests		64	67
Shareholders’ Equity (Note 12)
Common Shares, no par value
Authorized:	Unlimited
Outstanding:	2008 – 529,439,432 shares
	2007 – 528,304,813 shares	949	917
Contributed Surplus		3	3
Retained Earnings		5,600	4,983
Accumulated Other Comprehensive Loss		(266)	(293)
Total Shareholders’ Equity		6,286	5,610
Commitments, Contingencies and Guarantees (Note 16)
Total Liabilities and Shareholders’ Equity		19,661	18,075

See accompanying notes to the Unaudited Consolidated Financial Statements.

13

Nexen Inc.

Unaudited Consolidated Statement of Cash Flows

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Operating Activities
Net Income	630	121
Charges and Credits to Income not Involving Cash (Note 14)	383	435
Exploration Expense	32	49
Changes in Non-Cash Working Capital (Note 14)	140	32
Other	(17)	(189)
	1,168	448
Financing Activities
(Repayment of) Proceeds from Term Credit Facilities, Net	(228)	366
Proceeds from Term Credit Facilities of Canexus	8	18
Repayment of Short-Term Borrowings, Net	-	(48)
Dividends on Common Shares	(13)	(13)
Issue of Common Shares and Exercise of Stock Options	26	29
Other	(4)	(7)
	(211)	345
Investing Activities
Capital Expenditures
Exploration and Development	(769)	(790)
Proved Property Acquisitions	-	(1)
Chemicals, Corporate and Other	(17)	(20)
Changes in Restricted Cash	121	16
Changes in Non-Cash Working Capital (Note 14)	22	28
Other	(27)	(4)
	(670)	(771)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents	31	(13)
Increase in Cash and Cash Equivalents	318	9
Cash and Cash Equivalents – Beginning of Period	206	101
Cash and Cash Equivalents – End of Period	524	110

See accompanying notes to the Unaudited Consolidated Financial Statements.

14

Nexen Inc.

Unaudited Consolidated Statement of Shareholders’ Equity

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Common Shares
Balance at Beginning of Period	917	821
Issue of Common Shares	20	21
Proceeds from Tandem Options Exercised for Shares	6	8
Accrued Liability Relating to Tandem Options Exercised for Shares	6	16
Balance at End of Period	949	866
Contributed Surplus
Balance at Beginning and End of Period	3	4
Retained Earnings
Balance at Beginning of Period	4,983	3,972
Net Income	630	121
Dividends on Common Shares (Note 12)	(13)	(13)
Balance at End of Period	5,600	4,080
Accumulated Other Comprehensive Loss
Balance at Beginning of Period	(293)	(161)
Opening Derivatives Designated as Cash Flow Hedges	-	61
Other Comprehensive Income (Loss)	27	(67)
Balance at End of Period	(266)	(167)
Nexen Inc. Unaudited Consolidated Statement of Comprehensive Income For the Three months Ended March 31
(Cdn$ millions)	2008	2007
Net Income	630	121
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment:
Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations	186	(58)
Net Gains (Losses) on Hedges of Self-Sustaining Foreign Operations 1	(159)	50
Realized Translation Adjustments Recognized in Net Income 2	-	2
Cash Flow Hedges:
Realized Mark-to-Market Gains Recognized in Net Income	-	(61)
Other Comprehensive Income (Loss), Net of Income Taxes	27	(67)
Comprehensive Income	657	54

 

¹ Net of income tax expense for the three months ended March 31, 2008 of $23 million (2007 – $9 million recovery).

² Net of income tax expense for the three months ended March 31, 2008 of $nil (2007 – $1 million expense).

 

See accompanying notes to the Unaudited Consolidated Financial Statements.

15

Nexen Inc.

Notes to Unaudited Consolidated Financial Statements

Cdn$ millions, except as noted

1. ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States (US) GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 18. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.’s (Nexen, we or our) financial position at March 31, 2008 and December 31, 2007 and the results of our operations and our cash flows for the three months ended March 31, 2008 and 2007.

We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes, derivative contract assets and liabilities and determination of proved reserves, on an ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three months ended March 31, 2008 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2008.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.

Change in Accounting Policies

Inventories

In 2007, we adopted CICA Section 3031 Inventories issued by the Canadian Accounting Standards Board (AcSB). Effective October 1, 2007, we began carrying the commodity inventories held for trading by our energy marketing group at fair value, less any costs to sell. This standard was adopted prospectively and our results for the first three months of 2007 have not been restated for this change in accounting policy.

Capital Disclosures

On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity’s objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 7.

Financial Instruments Disclosures and Presentation

On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments – Disclosure (Section 3862) and Financial Instruments – Presentation (Section 3863). These accounting standards replaced Financial Instruments – Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 10 and 11.

New Accounting Pronouncements

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We are currently evaluating the impact these sections will have on our results of operations and financial position.

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and we will be required to report according to IFRS standards for the year ended December 31, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures.

16

2. ACCOUNTS RECEIVABLE

	March 31	December 31
	2008	2007
Trade
Marketing	2,907	2,501
Oil and Gas	931	819
Chemicals and Other	64	60
	3,902	3,380
Non-Trade	149	132
	4,051	3,512
Allowance for Doubtful Receivables	(10)	(10)
Total	4,041	3,502

3. INVENTORIES AND SUPPLIES

	March 31	December 31
	2008	2007
Finished Products
Marketing	659	577
Oil and Gas	20	14
Chemicals and Other	16	13
	695	604
Work in Process	4	3
Field Supplies	56	52
Total	755	659

4. DEFERRED CHARGES AND OTHER ASSETS

	March 31	December 31
	2008	2007
Long-Term Marketing Derivative Contracts (Note 10)	294	248
Long-Term Capital Prepayments	38	9
Crude Oil Put Options and Natural Gas Swaps (Note 10)	18	-
Asset Retirement Remediation Fund	13	13
Other	55	54
Total	418	324

17

5. SUSPENDED WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the three months ended March 31, 2008 and the year ended December 31, 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in property, plant & equipment.

	Three Months Ended March 31	Year Ended December 31
	2008	2007
Balance at Beginning of Period	326	226
Additions to Capitalized Exploratory Well Costs Pending the
Determination of Proved Reserves	49	215
Capitalized Exploratory Well Costs Charged to Expense	-	(10)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves	-	(74)
Effects of Foreign Exchange	7	(31)
Balance at End of Period	382	326

The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.

	March 31	December 31
	2008	2007
Capitalized for a Period of One Year or Less	195	202
Capitalized for a Period of Greater than One Year	187	124
Balance at End of Period	382	326
Number of Projects that have Exploratory Well Costs Capitalized for a Period
Greater than One Year	8	5

As at March 31, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interest in four exploratory blocks in the North Sea ($55 million), an exploratory block in the Gulf of Mexico ($54 million), our coalbed methane exploratory activities in Canada ($41 million), exploratory activities on Block 51 in Yemen ($19 million) and our interest in an exploratory block, offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to record proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or to assess commercial viability.

6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

	March 31	December 31
	2008	2007
Term Credit Facilities (a)	-	211
Canexus Limited Partnership Term Credit Facilities (US$213 million)	218	202
Medium-Term Notes, due 2008 (b)	125	125
Notes, due 2013 (US$500 million)	514	494
Notes, due 2015 (US$250 million)	257	247
Notes, due 2017 (US$250 million)	257	247
Notes, due 2028 (US$200 million)	205	198
Notes, due 2032 (US$500 million)	514	494
Notes, due 2035 (US$790 million)	812	781
Notes, due 2037 (US$1,250 million)	1,285	1,235
Subordinated Debentures, due 2043 (US$460 million)	473	454
	4,660	4,688
Less: Unamortized Debt Issue Costs	(77)	(78)
	4,583	4,610
Less: Current Portion of Long-Term Debt (b)	(125)	-
	4,458	4,610

18

(a) Term credit facilities

We have unsecured term credit facilities of US$3 billion available to 2012, none of which were drawn at March 31, 2008 (December 31, 2007 – US$214 million). Borrowings are available as Canadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 3.9% for the three months ended March 31, 2008 (2007 – 5.9%). At March 31, 2008, $296 million of these facilities were utilized to support outstanding letters of credit (December 31, 2007 – $283 million).

(b) Medium-Term Notes, due 2008

During October 1997, we issued $125 million of notes. Interest is payable semi-annually at a rate of 6.3% and the principal is to be repaid in June 2008. At December 31, 2007 this amount was not included in current liabilities as we expected to repay the principal using our term credit facilities. During the quarter, we reclassified this obligation to current liabilities as we now expect to repay this amount using our existing cash on hand.

(c) Interest expense

	Three Months Ended March 31
	2008	2007
Long-Term Debt	76	81
Other	4	5
	80	86
Less: Capitalized	(53)	(38)
Total	27	48

Capitalized interest relates to and is included as part of the cost of our oil and gas properties under development. The capitalization rates are based on our weighted-average cost of borrowings.

(d) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $666 million, none of which were drawn at March 31, 2008 (December 31, 2007 – nil). We have utilized $44 million of these facilities to support outstanding letters of credit at March 31, 2008 (December 31, 2007 – $196 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 4.3% for the three months ended March 31, 2008 (2007 – 5.9%).

7. CAPITAL DISCLOSURES

Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for our energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects, which require significant capital investment prior to cash flow generation, and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given year. As such, our financing needs depend on where we are in a particular development cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:

• maintaining an appropriate balance between short-term debt, long-term debt and equity, such as using longer-term senior and subordinated debt securities to minimize near-term refinancing risks;

• maintaining sufficient undrawn committed credit capacity to provide liquidity;

• ensuring ample covenant room permitting us to draw on our credit lines as required;

• maintaining a level of leverage with sufficient room for increases when necessary; and

• ensuring we maintain a credit rating that is appropriate for our circumstances.

19

We have the ability to make adjustments to our capital structure by issuing additional equity or debt, controlling the amount we return to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders’ equity, short-term and long-term debt and cash and cash equivalents (excluding restricted cash) as follows:

	March 31	December 31
	2008	2007
Net Debt 1
Bank Debt	218	413
Public Senior Notes	3,907	3,758
Senior Debt	4,125	4,171
Subordinated Debt	458	439
Total Debt	4,583	4,610
Less: Cash and Cash Equivalents	(524)	(206)
Total Net Debt	4,059	4,404
Shareholders’ Equity	6,286	5,610

¹ Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents.

We monitor our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage on a trailing 12 month basis that we feel are appropriate for Nexen.

We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure which is calculated using the GAAP measure of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).

For the twelve months ending March 31, 2008 our net debt to cash flow from operating activities ratio was 1.1 times compared to 1.6 times at December 31, 2007. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we devise a strategy to reduce our leverage and lower this ratio back to target levels. In the past, each time we exceeded our internal net debt to cash flow from operating activities target band, we successfully brought our leverage down through asset sales and capital management.

Our interest coverage ratio allows us to monitor our ability to meet the interest requirements of our capital and consequently the level, terms and condition of our debt profile. The higher the interest coverage, the better positioned we are to finance our longer-term investment projects. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 14.4 times at March 31, as our earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) increased from strong production and high commodity prices.

Interest coverage is calculated by dividing our twelve-month trailing EBITDA by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A and other non-cash expenses. The calculation of EBITDA is set out in the following table.

	Twelve Months Ended March 31 2008	Twelve Months Ended December 31 2007
Net Income	1,595	1,086
Add:
Interest Expense	147	168
Provision for Income Taxes	1,166	792
Depreciation, Depletion, Amortization and Impairment	1,797	1,767
Exploration Expense	309	326
Other Non-cash Expenses	(176)	(52)
EBITDA	4,838	4,087

20

8. ASSET RETIREMENT OBLIGATIONS  

Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows:

	Three Months Ended March 31	Year Ended December 31
	2008	2007
Balance at Beginning of Period	832	704
Obligations Incurred with Development Activities	2	105
Expenditures Made on Asset Retirements	(13)	(23)
Accretion	13	44
Revisions to Estimates	(1)	79
Effects of Foreign Exchange	21	(77)
Balance at End of Period 1, 2	854	832

 

¹     Obligations due within 12 months of $40 million (December 31, 2007 – $40 million) have been included in accounts payable and accrued
      liabilities.

²     Obligations relating to our oil and gas activities amount to $807 million (December 31, 2007 – $786 million) and obligations relating to our
      chemicals business amount to $47 million (December 31, 2007 – $46 million).

Our total estimated undiscounted asset retirement obligations amount to $2,200 million (December 31, 2007 – $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9%. Approximately $139 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations.

We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude’s upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the obligation to remediate becomes determinable.

9. DEFERRED CREDITS AND OTHER LIABILITIES

	March 31 2008	December 31 2007
Long-Term Marketing Derivative Contracts (Note 10)	225	163
Deferred Transportation Revenue	73	82
Defined Benefit Pension Obligations	58	57
Capital Lease Obligations	53	52
Fixed-Price Natural Gas Contracts (Note 10)	49	48
Other	67	57
Total	525	459

21

10. FINANCIAL INSTRUMENTS  

Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates their fair value because the instruments are near maturity.

In our energy marketing group, we enter into contracts to purchase and sell crude oil and natural gas and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). Occasionally, we use derivatives such as put options to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. Refer to the derivatives section below for details of our derivatives and fair values as at March 31, 2008. The fair value is included with accounts receivable or payable and they are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective interest rate method. At March 31, 2008, the estimated fair value of our long-term debt was $4,578 million (December 31, 2007 – $4,692 million) as compared to the carrying value of $4,583 million (December 31, 2007 – $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.

Derivatives

a) Total carrying value of derivative contracts related to trading activities

The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:

	March 31 2008	December 31 2007
Accounts Receivable	595	334
Deferred Charges and Other Assets 1	294	248
Total Derivative Assets	889	582
Accounts Payable and Accrued Liabilities	543	413
Deferred Credits and Other Liabilities 1	225	163
Total Derivative Liabilities	768	576
Total Net Derivatives related to Trading Activities	121	6

 

¹ These derivative contracts settle beyond 12 months and are considered non-current.

 

b) Total carrying value of derivative contracts related to non-trading activities

The fair value and carrying amounts related to derivative instruments related to non-trading activities are as follows:

	March 31 2008	December 31 2007
Accounts Receivable	8	-
Deferred Charges and Other Assets 1	18	1
Total Derivative Assets	26	1
Accounts Payable and Accrued Liabilities	36	28
Deferred Credits and Other Liabilities 1	49	51
Total Derivative Liabilities	85	79
Total Net Derivatives related to Non-Trading Activities	(59)	(78)

 

¹ These derivative contracts settle beyond 12 months and are considered non-current.

 

Crude oil put options

In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish an annual average Dated Brent floor price of $60/bbl on these volumes. In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options establish an annual average Dated Brent floor price of US$50/bbl on these volumes.

22

The put options are carried at fair value within amounts receivable and are classified as long-term or short-term based on their anticipated settlement date. Any changes in fair value are included in marketing and other income.

	Notional Volumes	Term	Average Floor Price	Fair Value
	(bbls/d)		(US$/bbl)	(Cdn$ millions)
Dated Brent Crude Oil Put Options	100,000	2008	50		-
Dated Brent Crude Oil Put Options	70,000	2009	60		14
					14

Fixed-price natural gas contracts and natural gas swaps

We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not included in our trading activities. These sales contracts and swaps are carried at fair value and are included with amounts receivable or payable. They are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.

	Notional Volumes	Term	Average Price	Fair Value
	(Gj/d)		($/Gj)	(Cdn$ millions)
Fixed-Price Natural Gas Contracts	15,514	2008	2.46		(36)
	15,514	2009 – 2010	2.56 – 2.77		(49)
Natural Gas Swaps	15,514	2008	7.60		8
	15,514	2009 – 2010	7.60		4
					(73)

c) Fair Value of Derivatives

Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net open sell and the bid price when we have a net open buy. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

We classify our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments.

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

• Level 3 – Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument’s fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily include extrapolation of observable future prices to similar locations, similar instruments or later time periods.

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The following table includes our derivatives that are carried at fair value on a recurring basis for our trading and non-trading activities as at March 31, 2008. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.

	Level 1	Level 2	Level 3	Total
Net Derivatives
Trading Derivatives	148	7	(34)	121
Non-Trading Derivatives	–	(59)	–	(59)
Total Net Derivatives	148	(52)	(34)	62

A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the three months ended March 31, 2008 is provided below:

	Level 3
Fair Value at January 1, 2008	(7)
Realized and unrealized gains (losses)	(5)
Purchases, issuances and settlements	(2)
Transfers in and/or out of Level 3	(20)
Fair Value at March 31, 2008	(34)
Unsettled gains (losses) relating to instruments still held as of March 31, 2008	(23)

Transfers in and/or out represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

11. RISK MANAGEMENT

(a) Market Risk

We invest in significant capital projects, purchase and sell commodities, issue short and long-term debt including amounts in foreign currencies and invest in foreign operations. These activities expose us to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage exposures to market risk that result from these activities.

The following market risk discussion relates primarily to commodity price risk and foreign exchange risk related to our financial instruments. Our exposure to interest rate risk is immaterial.

Commodity price risk

We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in world crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, such prices also may affect the value of our oil and gas properties and our level of spending for exploration and development.

The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. From time to time, we actively manage these risks by using derivative contracts such as commodity put options.

Our energy marketing group markets and trades crude oil, natural gas, NGLs, ethanol and power through physical purchase and sales contracts, as well as financial commodity contracts. These activities expose us to commodity price risk, as well as foreign currency risk and volatility within these markets. Our energy marketing group actively manages this risk by utilizing energy and currency derivatives. We typically take advantage of location, time and quality spreads using physical and financial contracts. The marketing group also tries to take advantage of volatility within commodity markets and can establish net open commodity positions to take advantage of existing market conditions.

Volatility within our various markets can vary and change over time. While this volatility gives us opportunities, it can also cause our results to vary significantly between periods. We attempt to manage associated risk and take on positions based on solid market intelligence; however, it is possible that we could incur financial loss.

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Open positions exist when not all contracted purchases and sales terms have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk sensitivities in our portfolio).

We manage the level of market risk through daily monitoring of our energy-trading activities relative to:

• prescribed limits for Value-at-Risk (VaR);

• nominal size of commodity positions;

• stop loss limits; and

• stress testing.

VaR is a statistical estimate assuming normal market conditions exist. Our VaR calculation estimates the maximum probable loss, given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility, correlation inputs where available and by historical simulation in other situations. Our estimate is based upon the following key assumptions:

• changes in commodity prices follow a statistical pattern of distribution;

• price volatility remains stable; and

• price correlation relationships remain stable.

If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We also use stress testing using extreme market movements which complements our VaR estimates. It is used to quantify potential unexpected losses from low probability market movements. Our VaR analysis incorporates our derivative positions, non-derivative transportation and storage contracts and assets, as well as commodity trading inventories.

Our quarter end, high, low, and average VaR amounts for the three months ended March 31 are as follows:

	Three months           ended March 31
	2008	2007
Value-at-Risk
Quarter End	35	33
High	40	35
Low	21	24
Average	30	28

Foreign currency risk

Foreign exchange risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:

• sales of crude oil, natural gas and certain chemicals products;

• capital spending and expenses for our oil and gas, Syncrude and chemicals operations;

• commodity derivative contracts used primarily by our energy marketing group; and

• short-term and long-term borrowings.

In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At March 31, 2008, we had US$4,413 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, before income tax.

In our energy marketing group, the majority of the financial commodity contracts are denominated in US dollars. We enter into US-dollar forward contracts and swaps to manage this exposure.

We also have immaterial exposures to currencies other than the US dollar. A portion of our United Kingdom operating expenses, capital spending and future asset retirement obligations are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies.

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(b) Credit Risk

Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. The majority of our accounts receivable are with counterparties in the energy industry and are subject to normal industry credit risk. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating occurs. Credit risk, including credit concentrations, is routinely reported to our management, including the Risk Management Committee. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance.

At March 31, 2008:

• over 97% of our credit exposures were investment grade; and

• only one counterparty individually made up more than 10% of our credit exposure. This counterparty was investment grade.

Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, as well as the fair value of derivative financial assets. There are no significant amounts past due or impaired at the balance sheet date. Collateral received from customers at March 31, 2008 includes $17 million of cash and $581 million of letters of credit related to our trading activities and the cash received is included in our accounts payable and accrued liabilities.

(c) Liquidity Risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to engage in our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At March 31, 2008, we had unsecured term credit facilities of US$3 billion available until 2012. At March 31, 2008, no amounts were drawn on these facilities, however, $296 million of the facilities were used to support outstanding letters of credit. We also had $666 million of undrawn, uncommitted, unsecured credit facilities, of which $44 million was supporting letters of credit at March 31, 2008.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at March 31, 2008:

	Total	< 1 Year	1-3 Years	4-5 Years	> 5 Years
Long-Term Debt	4,660	125	218	–	4,317
Interest on Long-Term Debt 1	6,593	219	548	548	5,278
Total	11,253	344	766	548	9,595

¹ Excludes interest on term credit facilities of US$3 billion and Canexus LP term credit facilities of $350 million as the amounts drawn on the facilities fluctuate. As a result, we are unable to provide a reasonable estimate of the interest.

The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.

	Total	< 1 Year	1–3 Years	4–5 Years	> 5 Years
Trading Derivatives	768	543	206	19	–
Non-Trading Derivatives	89	38	51	–	–
Total	857	581	257	19	–

The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event, such as a drop in credit ratings, occurs. Based on contracts in place and commodity prices at March 31, 2008, we could be required to post collateral of up to $1.7 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral merely secures the payment of such amounts.

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At March 31, 2008, collateral posted to our counterparties includes $36 million of cash and $200 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Letters of credit issued cannot be drawn on unless there has been default, which would have to be proven to the bank in order for them to release the funds. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained.

Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $75 million (December 31, 2007 – $203 million), which have been included in restricted cash.

12. SHAREHOLDERS’ EQUITY

Dividends

Dividends per common share for the three months ended March 31, 2008 were $0.025 (2007 – $0.025). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes.

13.  EARNINGS PER COMMON SHARE

Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 26, 2007. All common share and per common share amounts have been retroactively restated to reflect this share split.

We calculate basic earnings per common share using net income and the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.

	Three Months                Ended March 31
(millions of shares)	2008	2007
Weighted-average number of common shares outstanding	528.9	526.0
Shares issuable pursuant to tandem options	22.5	28.4
Shares notionally purchased from proceeds of tandem options	(14.2)	(15.8)
Weighted-average number of diluted common shares outstanding	537.2	538.6

In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2008, we excluded 4,103,560 tandem options, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2007, all options were included because their exercise price was less than the quarterly average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.

14. CASH FLOWS

(a) Charges and credits to income not involving cash

	Three Months              Ended March 31
	2008	2007
Depreciation, Depletion, Amortization and Impairment	364	334
Stock-Based Compensation	(59)	44
Future Income Taxes	77	35
Change in Fair Value of Crude Oil Put Options	-	16
Net Income Attributable to Non-Controlling Interests	1	3
Other	-	3
Total	383	435

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(b) Changes in non-cash working capital

	Three Months             Ended March 31
	2008	2007
Accounts Receivable	(446)	75
Inventories and Supplies	(78)	65
Other Current Assets	(10)	(4)
Accounts Payable and Accrued Liabilities	683	(58)
Accrued Interest Payable	13	(18)
Total	162	60
Relating to:
Operating Activities	140	32
Investing Activities	22	28
Total	162	60

(c) Other cash flow information

	Three Months           Ended March 31
	2008	2007
Interest Paid	66	101
Income Taxes Paid	85	57

Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $10 million for the three months ended March 31, 2008 (2007 – $10 million).

15. MARKETING AND OTHER INCOME

	Three Months            Ended March 31
	2008	2007
Marketing Revenue, Net	211	247
Change in Fair Value of Crude Oil Put Options	-	(16)
Interest	10	9
Foreign Exchange Gains (Losses)	5	(5)
Other	(4)	13
Total	222	248

16. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.

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17. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.

Three months ended March 31, 2008

						Energy		Corporate and
(Cdn$ millions)	Oil and Gas					Marketing	Syncrude	Chemicals	Other	Total
	Yemen	Canada	United States	United Kingdom	Other    Countries1
Net Sales	276	147	181	939	46	14	158	109	-	1,870
Marketing and Other	4	-	1	1	-	211	-	(7)	122	222
Total Revenues	280	147	182	940	46	225	158	102	12	2,092
Less: Expenses
Operating	45	42	24	57	3	9	62	67	-	309
Depreciation, Depletion, Amortization
and Impairment	34	47	74	170	4	3	12	10	10	364
Transportation and Other	2	5	1	-	-	173	5	19 3	-	205
General and Administrative 4	(2)	1	6	(1)	1	26	1	7	16	55
Exploration	-	4	6	7	155	-	-	-	-	32
Interest	-	-	-	-	-	-	-	3	24	27
Income (Loss)
before Income Taxes	201	48	71	707	23	14	78	(4)	(38)	1,100
Less: Provision for (Recovery
of) Income Taxes	70	14	25	359	3	1	22	-	(25)	469
Less: Non-Controlling
Interests	-	-	-	-	-	-	-	1	-	1
Net Income (Loss)	131	34	46	348	20	13	56	(5)	(13)	630
Identifiable Assets	341	5,8376	1,766	4,970	393	4,2717	1,216	476	391	19,661
Capital Expenditures
Development and Other	18	351	79	100	28	-	9	13	4	602
Exploration	5	86	67	16	10	-	-	-	-	184
	23	437	146	116	38	-	9	13	4	786
Property, Plant and Equipment
Cost	2,288	7,171	3,330	4,999	302	252	1,339	848	313	20,842
Less: Accumulated DD&A	2,068	1,637	1,898	1,085	84	65	214	474	178	7,703
Net Book Value	220	5,5346	1,432	3,914	218	187	1,125	374	135	13,139

¹     Includes results of operations from producing activities in Colombia.

²     Includes interest income of $10 million, foreign exchange gains of $5 million and other losses of $3 million.

³     Includes a severance accrual of $7 million in connection with North Vancouver technology conversion project.

⁴     Includes recovery of stock-based compensation expense of $41 million.

⁵     Includes exploration activities primarily in Nigeria, Norway and Colombia.

⁶     Includes costs of $4,003 million related to our Long Lake Project (Phase 1 and future phases).

⁷     Approximately 83% of Marketing’s identifiable assets are accounts receivable and inventories.

Three months ended March 31, 2007

						Energy			Corporate and
(Cdn$ millions)	Oil and Gas					Marketing	Syncrude	Chemicals	Other	Total
	Yemen	Canada	United States	United Kingdom	Other    Countries 1
Net Sales	243	115	168	344	29	16	119	106	-	1,140
Marketing and Other	3	1	-	4	-	247	-	5	(12)2	248
Total Revenues	246	116	168	348	29	263	119	111	(12)	1,388
Less: Expenses
Operating	42	39	28	53	2	13	47	66	-	290
Depreciation, Depletion,
Amortization and
Impairment	58	41	84	114	3	4	13	11	6	334
Transportation and Other	3	7	-	-	-	220	5	11	-	246
General and Administrative 3	1	32	19	5	24	30	-	9	82	202
Exploration	3	5	13	20	8 4	-	-	-	-	49
Interest	-	-	-	-	-	-	-	3	45	48
Income (Loss)
before Income Taxes	139	(8)	24	156	(8)	(4)	54	11	(145)	219
Less: Provision for (Recovery
of) Income Taxes	48	(2)	8	75	(1)	(1)	17	3	(52)	95
Less: Non-Controlling
Interests	-	-	-	-	-	-	-	3	-	3
Net Income (Loss)	91	(6)	16	81	(7)	(3)	37	5	(93)	121
Identifiable Assets	521	4,279 5	1,668	5,356	248	3,372 6	1,196	467	206	17,313
Capital Expenditures
Development and Other	32	356	139	140	8	-	7	12	8	702
Exploration	5	33	14	46	10	-	-	-	-	108
Proved Property Acquisitions	-	-	-	1	-	-	-	-	-	1
	37	389	153	187	18	-	7	12	8	811
Property, Plant and Equipment
Cost	2,414	5,601	2,982	4,834	256	230	1,305	797	294	18,713
Less: Accumulated DD&A	2,121	1,485	1,491	528	81	49	185	436	154	6,530
Net Book Value	293	4,116 5	1,491	4,306	175	181	1,120	361	140	12,183

 

¹ Includes results of operations from producing activities in Colombia.

² Includes interest income of $9 million, foreign exchange losses of $5 million and decrease in the fair value of crude oil put options of $16 million.

³ Includes stock-based compensation expense of $116 million.

⁴ Includes exploration activities primarily in Nigeria, Norway and Colombia.

⁵ Includes costs of $2,847 million related to our Long Lake Project (Phase 1 and future phases).

⁶ Approximately 78% of Marketing’s identifiable assets are accounts receivable and inventories.

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18. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows:

(a) Unaudited Consolidated Statement of Income – US GAAP

For the Three Months ended March 31

(Cdn$ millions, except per share amounts)	2008	2007
Revenues and Other Income
Net Sales	1,870	1,140
Marketing and Other (i); (vii)	206	246
	2,076	1,386
Expenses
Operating (ii)	310	296
Depreciation, Depletion, Amortization and Impairment	364	334
Transportation and Other	205	246
General and Administrative (iii)	62	199
Exploration	32	49
Interest	27	48
	1,000	1,172
Income before Income Taxes	1,076	214
Provision for Income Taxes
Current	392	60
Deferred (i) – (vii)	66	33
	458	93
Net Income before Non-Controlling Interests	618	121
Net Income Attributable to Non-Controlling Interests	(1)	(3)
Net Income – US GAAP 1	617	118
Earnings Per Common Share ($/share)
Basic (Note 13)	1.17	0.23
Diluted (Note 13)	1.15	0.22

Note:

1	Reconciliation of Canadian and US GAAP Net Income
		Three Months       Ended March 31
	(Cdn$ millions)	2008	2007
	Net Income – Canadian GAAP	630	121
	Impact of US Principles, Net of Income Taxes:
	Ineffective Portion of Cash Flow Hedges (i)	-	(2)
	Pre-operating Costs (ii)	(1)	(3)
	Inventory Valuation (vii)	(7)	-
	Stock-based Compensation (iii)	(5)	2
	Net Income – US GAAP	617	118

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(b) Unaudited Consolidated Balance Sheet – US GAAP  

	March 31	December 31
(Cdn$ millions, except share amounts)	2008	2007
Assets
Current Assets
Cash and Cash Equivalents	524	206
Restricted Cash	75	203
Accounts Receivable	4,041	3,502
Inventories and Supplies (vii)	695	615
Deferred Income Tax Asset	25	18
Other	84	71
Total Current Assets	5,444	4,615
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $8,096 (December 31, 2007 – $7,588) (ii); (v)	13,089	12,449
Goodwill	337	326
Deferred Income Tax Assets	263	268
Deferred Charges and Other Assets	418	324
Total Assets	19,551	17,982
Liabilities and Shareholders’ Equity
Current Liabilities
Short-Term Borrowings	125	-
Accounts Payable and Accrued Liabilities (iii)	4,954	4,233
Accrued Interest Payable	67	54
Dividends Payable	13	13
Total Current Liabilities	5,159	4,300
Long-Term Debt	4,458	4,610
Deferred Income Tax Liabilities (i) – (vii)	2,344	2,230
Asset Retirement Obligations	814	792
Deferred Credits and Liabilities (iv)	600	534
Non-Controlling Interests	64	67
Shareholders’ Equity
Common Shares, no par value
Authorized:   Unlimited
Outstanding:   2008 – 529,439,432 shares
2007 – 528,304,813 shares	949	917
Contributed Surplus	3	3
Retained Earnings (i) – (vii)	5,480	4,876
Accumulated Other Comprehensive Loss (i); (iv)	(320)	(347)
Total Shareholders’ Equity	6,112	5,449
Commitments, Contingencies and Guarantees
Total Liabilities and Shareholders’ Equity	19,551	17,982

(c) Unaudited Consolidated Statement of Comprehensive Income – US GAAP

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Net Income – US GAAP	617	118
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment	(27)	(6)
Change in Mark to Market on Cash Flow Hedges (i)	-	(61)
Comprehensive Income	590	51

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(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive Income – US GAAP

	March 31	December 31
(Cdn$ millions)	2008	2007
Foreign Currency Translation Adjustment	(266)	(293)
Unamortized Defined Benefit Pension Costs (iv)	(54)	(54)
	(320)	(347)

Notes:

i. Under US GAAP, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. On January 1, 2007, we adopted the equivalent Canadian standard for derivative instruments.

Future sale of gas inventory: At December 31, 2006, we included $25 million of gains on cash flow hedges in accounts receivable. Accumulated Other Comprehensive Income (AOCI) includes the effective portion of $23 million ($16 million, net of taxes) and $2 million ($2 million, net of taxes) of the ineffective portion in our US GAAP net income. Under Canadian GAAP, these gains were recognized in the first quarter of 2007.

At March 31, 2008, there were no cash flow hedges in place.

ii. Under Canadian GAAP, we defer certain development costs and all pre-operating revenues and costs to property, plant and equipment. Under US principles, these costs have been included in operating expenses. As a result:

• operating expenses include pre-operating costs of $1 million for the three months ended March 31, 2008 ($1 million, net of income taxes) (2007 – $6 million ($3 million, net of income taxes)); and

• property, plant and equipment is lower under US GAAP by $31 million (December 31, 2007 – $30 million).

iii. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. We are also required to accelerate the recognition of stock-based compensation expense for all stock-based awards made to our retirement-eligible employees under Canadian GAAP. However, under US GAAP, the accelerated recognition for such employees is only required for stock-based awards granted on or after January 1, 2006. As a result:

• general and administrative expense is higher by $7 million ($5 million, net of income taxes) for the three months ended March 31, 2008 (2007 – lower by $3 million ($2 million, net of income taxes)); and

• accounts payable and accrued liabilities are higher by $60 million as at March 31, 2008 (December 31, 2007 – $53 million).

iv. On December 31, 2006, we adopted FASB Statement 158 Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). At March 31, 2008, the unfunded amount of our defined benefit pension plans was $75 million. This amount has been included in deferred credits and other liabilities and $54 million, net of income taxes has been included in AOCI.

v. On January 1, 2003, we adopted FASB Statement 143, Accounting for Asset Retirement Obligations (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our property, plant and equipment under US GAAP being lower by $19 million.

vi. On January 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48) with respect to FAS 109 Accounting for Income Taxes regarding accounting and disclosure for uncertain tax positions. On the adoption of FIN 48, we recorded a cumulative effect of a change in accounting principle of $28 million. This amount increased our deferred income tax liabilities, with a corresponding decrease to our retained earnings as at January 1, 2007 in our US GAAP – Unaudited Consolidated Balance Sheet. As at March 31, 2008, the total amount of our unrecognized tax benefits was approximately $223 million, all of which, if recognized, would affect our effective tax rate. As at March 31, 2008, the total amount of interest and penalties in relation to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP –Unaudited Consolidated Balance Sheet is approximately $10 million. We had no interest or penalties in the US GAAP – Unaudited Consolidated Statement of Income for the first quarter of 2008. Our income tax filings are subject to audit by taxation authorities and as at March 31, 2008 the following tax years remained subject to examination; (i) Canada – 1985 to date, (ii) United Kingdom – 2002 to date and (iii) United States – 2004 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months.

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vii. Under Canadian GAAP, we began carrying our commodity inventory held for trading purposes at fair value, less any costs to sell effective October 31, 2007. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result:

• marketing and other income is lower by $16 million ($7 million, net of income taxes) for the three months ended March 31, 2008; and

• inventories are lower by $60 million as at March 31, 2008 (December 31, 2007 – $44 million).

Changes in Accounting Policies–US GAAP

During the quarter, we adopted FASB Statement 157 Fair Value Measurements which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The adoption of this statement did not have a material impact on our results of operations or financial position. The additional disclosures required by the statement are included in Note 10.

New Accounting Pronouncements–US GAAP

Effective December 31, 2006, we adopted the recognition and disclosure provisions of FASB Statement 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement also requires measurement of the funded status of a plan as of the balance sheet date. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. We do not expect the adoption of the change in measurement date in 2008 will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 141 (revised), Business Combinations. Statement 141 (revised) establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 160, Non-controlling Interests In Consolidated Financial Statements, an amendment of ARB. No. 51. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

In March 2008, FASB issued Statement 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged positions. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. This statement is effective for fiscal years and interim periods beginning on or after November 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

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